Engineering & Mining Journal

AUG 2017

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Page 27 of 99

OIL SANDS
26 E&MJ • AUGUST 2017 www.e-mj.com
ty for their reinstatement once prices rise
above break-even again.
And that in turn raises some inter-
esting questions about what production
costs in the oil sands industry really are,
and what the impact of the low oil price is
likely to be on future investment plans.
At the end of 2015, IHS Energy pub-
lished a report that looked at this and
other issues relating to oil sands develop-
ment costs. In Oil Sands Cost and Com-
petitiveness, the company estimated the
break-even economics for new projects,
both mines and in situ, noting that "the
full-cycle cost — the total cost to find,
develop, and ultimately produce oil is of-
ten expressed as the price per barrel of
oil required for an investment in new oil
production to break even (with a 10% in-
ternal rate of return)."
According to IHS, "on average in
2015 a new oil sands mine required a
West Texas Intermediate (WTI) price be-
tween US$85 and $95/bbl to cover all
the costs associated with a project with
capacity to produce 100,000 bbl/d of di-
luted bitumen. An in-situ SAGD project
requires between US$55 and $65/bbl
to produce 30,000 bbl/d of diluted bitu-
men," the company went on, adding that
"SAGD expansions require prices about
US$5/bbl less."
The company qualified these esti-
mates by pointing out that "although
prices in 2015 were below the break-even
threshold for new projects (explaining why
many have been deferred), an existing fa-
cility should have, on average, received
sufficient revenue to cover its day-to-day
operating costs."
That was in late 2015, so what has
happened to the price of WTI since then?
In reality, not much to keep oil sands op-
erators happy, albeit that the price at the
beginning of July (US$44.40/bbl) was
somewhat better than the nadir of below
US$29 recorded in January 2016. In the
interim, the price had indeed flirted with
US$50 and above, but even that would
have meant slim margins for several of
the established producers.
Increasing productivity and cutting
costs have been the order of the day all
round since the oil price collapse in 2014
and 2015. And some companies have
not only been successful, but have been
quick to advertise that success.
For example, Canadian Natural re-
ported record low annual average op-
erating costs of C$25.20/bbl in 2016,
after adjusting for planned downtime at
its Horizon mine, representing a 12%
fall year-on-year. In addition, the compa-
ny did even better in the last quarter of
the year, reflecting the ramp-up of new
capacity through its Phase 2B expansion,
reporting quarterly production costs at
C$22.53/bbl. As a result, it has revised
its 2017 cost estimate down to C$24-
$27/bbl, including planned downtime for
maintenance, turnaround and tie-in activ-
ities relating to its Phase 3 expansion.
Meanwhile, Suncor managed to cut its
cash production costs during the year to
C$26.50/bbl, 5% down year-on-year and
the lowest the company had achieved
since 2007. It was helped in this respect
by its acquisition of a greater share of
output from Syncrude, which, it reported,
achieved average utilization rates of 97%
and cash operating costs of a little more
than C$30/bbl during the year. This, Sun-
cor added, was "a notable improvement
on the 71% utilization rate and C$42/bbl
achieved in 2015. In fact, the third and
fourth quarters represented the best six
months of production that the Syncrude
facility has ever achieved," the company
stated in its annual report.
Mine Capacity Rising...
The next mine to be commissioned in the
area to the north of Fort McMurray, Fort
Hills, is scheduled to produce its first oil
late this year. At the end of 2016, minori-
ty partner in the project, Teck Resources,
reported that construction was then more
than 76% complete, with the project's
mining and infrastructure sectors turned
over to operations. All major plant equip-
ment and materials were on site, and all
major vessels and process modules had
been installed at that stage.
However, Teck also noted that the im-
pact of the huge wildfire last year together
with productivity challenges have caused
an increase in the capital cost estimate for
the secondary extraction facility, with the
revised total capex forecast about 10%
higher than the project sanction estimate,
excluding foreign exchange impacts. In
this respect, changes in the Canadian
dollar exchange rate have added around
C$300 million to the project cost, which
is now estimated at between C$16.5 and
C$17 billion. Since the project operator,
Suncor, has announced an 8% increase in
the nameplate capacity to 194,000 bbl/d,
the capex cost per flowing barrel of bitu-
men will remain at C$84,000. Operating
costs of around C$23.40/bbl are expected
over the life of the project.
Fort Hills will use traditional open-pit
truck and shovel mining, with value-add-
ed carbon-rejecting solvent-extraction
technology that will allow the operation to
produce a higher quality and lower green-
house gas (GHG)-intensity bitumen prod-
uct that can be sold directly to the mar-
Steam generators at the Christina Lake in-situ operation, now wholly owned by Cenovus Energy after ConocoPhillips
sold its stake earlier this year. Cutting the amount of steam needed to liberate and fluidize the bitumen
underground is a key target for cost and emissions-reduction efforts in the oil sands industry.